Oil and gas wells are typically drilled with a rotary drill bit, and the resulting borehole is cased with steel casing cemented in the borehole to support pressure from the surrounding formation. Hydrocarbons may then be produced through smaller diameter production tubing suspended within the casing. Although fluids can be produced from the well using internal pressure within a producing zone, pumping systems are commonly used to lift fluid from the producing zone in the well to the surface of the earth. This is often the case with mature producing fields where production has declined and operating margins are thin.
The most common pumping system used in the oil industry is the sucker rod pumping system. A pump is positioned downhole, and a drive motor transmits power to the pump from the surface with a sucker rod string positioned within the production tubing. Rod strings include both “reciprocating” types, which are axially stroked, and “rotating” types, which rotate to power progressing cavity type pumps. The latter type is increasingly used, particularly in wells producing heavy, sand-laden oil or producing fluids with high water/oil ratios. The rod string can consist of a group of connected, essentially rigid, steel or fiberglass sucker rod sections or “joints” in lengths of 25 or 30 feet. Joints are sequentially connected or disconnected as the string is inserted or removed from the borehole, respectively. Alternatively a continuous sucker rod (COROD) string can be used to connect the drive mechanism to the pump positioned within the borehole.
A number of factors conspire to wear down and eventually cause failure in both sucker rods and the production tubing in which they move. Produced fluid is often corrosive, attacking the sucker rod surface and causing pitting that may lead to loss of cross-sectional area or fatigue cracking and subsequent rod failure. Produced fluid can also act like an abrasive slurry that can lead to mechanical failure of the rod and tubing. The rod and tubing also wear against each other. Such wear may be exacerbated where the well or borehole is deviated from true vertical. Even boreholes believed to have been drilled so as to be truly vertical and considered to be nominally straight may deviate considerably from true vertical, due to factors such as drill bit rotational speed, weight on the drill bit, inherent imperfections in the size, shape, and assembly of drill string components and naturally-occurring changes in the formation of the earth that affect drilling penetration rate and direction. Also, some boreholes are intentionally drilled at varying angles using directional drilling techniques designed to reach different parts of a hydrocarbon-producing formation. As a result, sucker rods and production tubing are never truly concentric, especially during the dynamics of pumping, and instead contact one another and wear unpredictably over several thousand feet of depth. Induced wear is therefore a function of many variables, including well deviation from true vertical; angle or “dogleg” severity; downhole pump operating parameters; dynamic compression, tensile and sidewall loads; harmonics within the producing sucker rod string; produced solids; produced fluid lubricity; and water to oil ratio. Additionally, in certain conditions, such as in geologically active areas or in areas of hydrocarbon production from diatomite formations, wellbores may shift over time, causing additional deviation from vertical.
Boreholes deviate considerably from true vertical due to various factors, including drill bit rotational speed, weight on the drill bit, inherent imperfections in the size, shape, and assembly of drill string components and naturally-occurring changes in the formation of the earth. When using a tubing anchor to rigidly fix the lower part of a tubing string in a wellbore relative to the casing, it is often necessary to apply a tensile load to the tubing string to prevent sags or kinks in the tubing in certain zones of the wellbore. In certain conditions, such as in geologically active areas or in areas of hydrocarbon production from diatomite formations, producing wells may shift over time, causing additional deviation from vertical. As a result, sucker rods and production tubing are often never truly concentric, especially during the dynamics of pumping, and instead contact one another and wear in certain areas, some of which are known as “doglegs”, or where the tubing sags or is kinked. Without a continuous deviation survey of the wellbore, it is difficult, if not impossible, to identify areas where the well deviation from vertical results in contact and wear of the rods and tubing.
For many years it has been possible to determine the deviation of a borehole, or wellbore, from true vertical. Such techniques are used extensively in the drilling of new wellbores, either as periodic “single shot” surveys, “multishot” surveys or even continuously while drilling, known as “MWD”. U.S. Pat. No. 6,453,239 to Shirasaka, et al, U.S. Pat. No. 5,821,414 to Noy, et al, U.S. Pat. No. 4,987,684 to Andreas, et al and U.S. Pat. No. 3,753,296 to Van Steenwyk, disclose such examples of surveying wellbores. However, in the case of most existing rod-pumped oil wells, any such surveys performed during the original drilling of the well largely comprised periodic surveys of wellbore direction and inclination performed only at one or two key intervals during the well-drilling operation. Consequently, a continuous profile of the wellbore deviation, giving rise to tubing and rod wear, is not generally known. Alternatively, performing a dedicated, continuous directional survey of existing wellbores, such as those contemplated in the above patents, is generally cost-prohibitive. There is a need for a cost-effective directional survey that can be integrated into well work-over operations of existing producing wellbores to obtain an accurate, nearly continuous deviation profile and allow mitigation of rod and tubing wear.
Prior art wellbore deviation techniques and tools are generally designed for the measurement of a wellbore while drilling, or are used on wireline or slickline during the process of drilling, to measure the direction and inclination of the wellbore with respect to an as-yet un-reached planned trajectory or target of interest. Prior art accelerometer and magnetometer deviation tools are also typically capable of determining wellbore inclination and azimuth only outside of the presence of magnetic interference, e.g., in open, uncased wellbores.
Oil well production string inspection methods conventionally use magnetic flux leakage techniques and typically rely only upon signal amplitude and time-based denominations or, in some cases, signal amplitude and wellbore depth, to provide the equipment operator with information representing the sucker rod or tubing string condition. U.S. Pat. Nos. 2,555,853, 2,855,564, 4,492,115, 4,636,727, 4,715,442, 4,843,317, 5,914,596, 6,316,937 disclose methods and apparatus to perform magnetic flux leakage inspections of sucker rods and tubing as elements of the production wellbore.
The amplitude of a magnetic flux leakage signal from a flaw in a ferromagnetic material under test is a function of many variables, including magnetic permeability of the material under test; magnetizing field strength; detection sensor type; sensor-to-material-under-inspection stand-off; flaw orientation relative to magnetic field direction; flaw volume; flaw depth, flaw shape; sensor-to-material-under-inspection relative velocity; sensor signal filtering and; sensor signal-to-noise ratio, among others. Conventional systems that rely only upon amplitude and time, or upon amplitude and wellbore depth, are susceptible to misinterpretation since the apparent flaw signal amplitude may be a function of many factors other than depth alone. Many such systems do not employ field standardization techniques to establish flaw standardization levels for inspection. Even those methods that do employ standardization techniques rely upon signal amplitude alone for flaw severity analysis.
Some prior art gyroscope and accelerometer deviation tools, of either the gimballed or strapped-down type, are capable of use inside cased hole and are generally used during the drilling process. U.S. Pat. No. 4,468,863 discloses a single shot or periodic multi-shot survey tool deployed on a wireline. U.S. Pat. No. 5,821,414 discloses a system for measuring deviation and inclination, while a wellbore is being drilled, to achieve an ultimate bottom hole location that positions the wellbore to optimally drain the target hydrocarbon reservoir. Most Measurement-While-Drilling applications that are intended for open hole, high temperature, high pressure environments, as disclosed in U.S. Pat. No. 6,714,870 to Weston, et al. Such tools are typically large, insulated, shock-absorbing, high pressure- and temperature-resistant to handle the extremely demanding environment of drilling in extreme temperature, vibration and pressure, as disclosed in U.S. Pat. No. 4,302,886. Systems may utilize relatively gimbaled gyroscopes or expensive and complex Coriolis-effect strapped-down gyroscopes, as disclosed in U.S. Pat. No. 6,453,239. Such tools are generally too large and lengthy to be used inside small diameter production tubing, and too expensive for most pumped well application. The high cost of these systems prohibits consideration by the operators of relatively shallow, existing rod-pumped, producing wells in the declining fields of mature sedimentary basins.
Failure of pumped oil wells due to the cumulative effect of the wear of sucker rods on tubing and such wear combined with corrosion is considered to be the single largest cause of well down time. Generally accepted methods of mitigating such wear include installing rod guides to centralize the sucker rod in the tubing with selected tubing surface contact materials; sinker bars to add weight to the sucker rod string; tubing insert liners composed of wear-resistant materials such as nylon and polythene; and improving operational practice. Examples of rod guides are disclosed in U.S. Pat. No. 6,152,223 to Abdo, U.S. Pat. No. 5,339,896 to Hart, U.S. Pat. No. 5,115,863 to Olinger, and U.S. Pat. Nos. 5,492,174 and 5,487,426 to O'Hair. An example of a tubing liner insert is U.S. Pat. No. 5,511,619 to Jackson. Since many of these mitigation techniques are expensive to apply, oil well operators must carefully assess the economics of any such mitigation techniques.
Although wear can be mitigated, it cannot be eliminated, so inspection of sucker rods and production tubing are common in the industry. Well operators within the industry commonly follow a “run until failure” approach, only inspecting components upon failure of some element of the wellbore, which may include a hole or split in the tubing, pump failure, rod failure, or tubing separation. The nature of the industry is that down-time is costly, both in terms of lost or deferred production and the actual cost to repair the failure by work-over of the wellbore. Another reason well operators are reluctant to perform inspections at regular intervals is that the diagnostic capabilities of current inspection practices are somewhat limited. A more useful, reliable, and economical method of wear and corrosion pattern analysis and diagnosis that gives rise to mitigation opportunities would allow operators to be more proactive. Further, many operators are unable to devote the time and human resources to perform the necessary analysis of data such as well deviation, rod failure and tubing failure.
The most basic wear analysis techniques include simply observing the wear patterns contained within the individual lengths of oil well production tubing, to empirically inspect tubing for wall thickness loss due to mechanical wear and corrosion of sucker rods and tubing. Caliper surveys are available to measure the inside diameter of production tubing but cannot examine the condition of the outside condition of the tubing.
More sophisticated inspection techniques employ magnetic sensor technologies to assess the condition of production tubing. Magnetic testing devices have been known for many years, as disclosed in U.S. Pat. No. 2,555,853 to Irwin and more specifically for oilfield tubulars and sucker rods in U.S. Pat. No. 2,855,564 to Irwin for a Magnetic Testing Apparatus and Method. Applying this technology to the inspection of oilfield tubulars, U.S. Pat. Nos. 4,492,115, 4,636,727 and 4,715,442 disclose tubing trip tools and methods for determining the extent of defects in continuous production tubing strings during removal from the well. The tools and methods include magnetic flux leakage sensor coils and Hall effect devices for detecting defects such as average wall thickness, corrosion, pitting, and wear. One or more of the above tools further include a velocity and position detector for correlating the location of individual defects to their locations along the tubing string. A profile of the position of the defects in the continuous string can also be established.
U.S. Pat. No. 4,843,317 to Dew discloses a method and apparatus for measuring casing wall thickness using an axial main coil for generating a flux field enveloping the casing wall. U.S. Pat. No. 6,316,937 to Edens discloses a combination of magnetic Hall effect sensors and digital signal processing to evaluate defects and wear. U.S. Pat. No. 5,914,596 to Weinbaum discloses a magnetic flux leakage and sensor system to inspect for defects and measure the wall thickness and diameter of continuous coiled tubing. All of these systems induce magnetic flux within the tubing. Surface defects result in magnetic flux leakage. Sensors measure the leakage and are thereby used to locate and quantify the surface defect.
Techniques are also known for magnetically inspecting sucker rods. Conventional sucker rod segments are commonly removed from an oil well, separated, and trucked to inspection plants to be “reclaimed”. U.S. Pat. No. 2,855,564 to Irwin discloses a magnetic testing apparatus used in inspection of sucker rods, and U.S. Pat. No. 3,958,049 to Payne discloses an example of a process for reclaiming used sucker rod. In the latter patent, the salvaged rod is degreased, visually inspected, subjected to a shot peening operation, and analyzed for structural imperfections. Magnetic induction techniques are employed, albeit at an inspection plant, rather than on-site. A system for evaluating a coiled sucker rod string, or “COROD”, as it is pulled from a well is disclosed in U.S. Pat. No. 6,580,268. Defects within the COROD may be correlated with their position. The system generates “real time” calculated dimensional display of the COROD and cross-sectional area as a function of position. Wireless technology can be used, such as to convey signals from a processor unit as many as 200 feet to a laptop server.
Aspects of the sucker rod and production tubing inspection techniques discussed above have a certain level of sophistication, such as the use of wireless technology and digital signal processing. Ironically, however, the analyses derived from the resulting data are relatively limited and shortsighted. The data obtained is not optimally used to correct or mitigate wear. For example, the end result of conventional sucker rod inspection and reclamation is the rather simplistic determination of whether to re-classify and reuse or dispose of each rod.
Additionally, because the production tubing in most rod-pumped producing wells is tubing that has previously been used in other wells or from such reclaimed supplies, pre-existing wear patterns on tubing alone are often misleading as to the root causes of tubing wear in the current wellbore. Further, even a detailed, positional analysis of defects does not provide an adequate window as to their root cause or mitigation. For example, in general, well operators simply reposition rod guides, which may merely shift wear on the rod or tubing to another position along the string. An alternative technique to mitigate rod wear on tubing is disclosed in U.S. Pat. No. 36,362E to Jackson, whereby an abrasion resistant polymer, such as polyethylene, is inserted into the tubing. This technique, however, reduces the inside diameter of the tubing and does not assess the cause of tubing wear. As a result, the polythene liner may simply fail over time, rather than the tubing, which still necessitates work-over. Not even “real time” data reports provide an adequate solution to mitigating wear, because they do nothing to improve the quality or scope of the analysis, or correlate tubing condition information with rod condition information. An accurate analysis of the cause of wellbore failure due to tubing or rod failure is also aided with a profile of the wellbore deviation.
Another problem with existing inspection systems is that there is no available means of performing these assessments in a cost-effective and timely manner so that tubing wear can be mitigated through an economical solution specific to a well. Because quickly returning the well to production is of paramount importance, full analysis of any limited information available is often difficult, if not impossible, to perform before the well is returned to production.
The disadvantages of the prior art are overcome by the present invention. An improved system is provided for evaluating and mitigating one or more of wear and corrosion on rod strings and/or tubular strings while being pulled from a wellbore.